Remember back when everybody hated electricity deregulation?
Today we take a break from our regularly scheduled blogging about environmental topics to provide a brief message concerning electricity restructuring. Severin Borenstein and I are finishing up a draft paper for the Annual Review of Economics (available as a working paper here) that looks back over the last 20 years of electricity restructuring and it has given us a chance to update some data sets and revisit some topics that really haven’t gotten a lot of attention since around 2008.
Around that time I started giving a talk titled “If electricity restructuring is so great, why does everybody hate it?” Back then, several states like Illinois and Maryland were actively pursuing options to “re-regulate” markets that they had at least partially restructured. The New York Times ran a series of articles that pointed to studies showing that rates had increased more rapidly in states that had restructured compared to those that did not. The gist of my talk was that this could very well be true, but did not necessarily signal that restructuring was a failure.
Back in 2000, Severin and I had written a paper arguing that the motivations for restructuring were driven more by a desire by some groups to avoid paying for stranded assets (like nuclear and coal plants which looked like white elephants in the late 1990s) than by a belief that restructuring would reap massive efficiency gains. In economic terms, customers preferred to pay market-based prices — which were based upon marginal cost in competitive markets — rather than regulated rates — which were based upon average production costs. During this period of relatively large capacity margins and low natural gas prices, market-based pricing appealed to customers and terrified utility shareholders whose assets would become stranded absent other compensation. However, despite the allure of market-based pricing, the regulatory and political process allowed utilities to recover the bulk of what appeared at the time to be stranded costs. So customers ended up paying for most of these costs anyway.
The great irony of this period is that a half decade after transition arrangements largely compensated utilities for the losses incurred in selling or transferring these assets, the market value of those same assets had fully recovered. By the mid-2000s the relationship between average and marginal cost had largely reversed, and states like Illinois and Maryland expressed a great deal of regret about the decision to restructure. However, since the formerly regulated generation assets were now largely held by private, deregulated firms, there was no clear path to dramatically “re-regulate” the industry without paying full market value for those assets. Looked at this way, one can view the disappointment with restructuring as being driven by magnificently poor market timing. Utilities sold off their assets at the nadir of their value, and as natural gas prices climbed throughout the 2000s, those assets became quite valuable under market-based pricing. Therefore, my take on this topic circa 2008 was that, with hindsight certain states would have been better off restructuring, but that was due to external shocks like natural gas price increases and changes in technologies.
States by Percentage of Generation from IPP sources
Then a funny thing happened. Since 2009, this story has largely reversed yet again. Natural gas prices have declined sharply, nearly to the levels seen at the dawn of the restructuring movement. The attention of policymakers has now been consumed by environmental priorities, particularly the implications of coal generation decline and renewable generation growth for costs and greenhouse gas emissions. A surge of subsidized renewable generation, combined with low natural gas prices, has driven wholesale prices steadily lower. As one would expect, in the short run this has benefited consumers in market-based states disproportionately more than those in regulated states. This figure plots the average prices of electricity and natural gas in “restructured” states (defined as a state with more than 40% of its energy produced from IPP sources – the states that are not blue in the figure above) and “regulated” states. The dashed line shows the difference between the two groups. One can see the gap between the states growing as natural gas prices climb, and then following the natural gas prices right down again.
The table below summarizes the changes in rates using two different definitions of restructured that are explained in the paper. All together if you look at the changes in between the two groups now, restructured states actually come out a little better than the regulated states. Rates kept rising at a consistent trend in regulated states, while they have declined slightly in the restructured ones.
This is not meant to be a comprehensive study of rate differences. For example, we suspect that Renewable Portfolio Standards requirements in some states, like California, are keeping rates from declining faster. But I do find it fascinating that the situation has reversed so dramatically over the last 5 or 6 years. Not surprisingly, there isn’t much clamoring for re-regulation these days.
You also don’t see much clamoring for more restructuring either, however, which is equally interesting. The relationship between average costs and marginal costs appears again to be turning in favor of marginal costs, but today the resulting pressure is being manifested in the arena of distributed generation, rather than retail choice. Although rooftop solar and retail competition are not usually equated, from a consumer perspective the economics of each can be very similar. Both have been pushed forward in large part by a desire to avoid paying for sunk costs – generation in the case of retail competition and distribution costs in the case of distributed generation.
However, looked at from a societal perspective, such motivations can be disheartening. Consider the prospect, hinted at in this article, of a future where homes install batteries and distributed generation in order to avoid paying for fixed distribution charges. Even if this becomes economically viable from a household perspective, this is a potentially appalling waste of resources. We would be talking about thousands of dollars of investment per household to avoid paying for assets that are already there. Who pays for these wires? Either utility shareholders or those households that don’t leave the grid.
There are real and important technological and efficiency advances happening, and competition is providing some of the impetus for that. But much of the economics and politics of this industry have been and still are dominated by the not-very-noble desire to stick someone else with existing infrastructure costs.
From the perspective of large institutions, the decision to support and become involved in the restructured electricity market in 1998 was based on the fact that lower electricity bills achieved through purchases of electricity at the wholesale level would, and did, result in lower electricity bills which in turn allowed those large institution to invest in on site generation and on site distribution which was more reliable, more efficient, and in some cases a step away from fossil fuels. It is now observed that these large institutions and even individual home owners are coming to the conclusion that on site generation and on site distribution can achieve these same goals (more reliable, more efficient use of energy, and included the step away from fossil fuels). Conceivably, the energy power pack for the homeowner is going to be as available as the water heater. This leaves the IOUs with the role of supplying the back up power, which can be obtained for a price which includes all the stranded costs, the sellers of energy power packs, or the overseers of the hydrogen pipe line.
If hydrolysis becomes cost effective, hydrogen is shipped most effectively as water.
I am glad that you and Severin are working on an electricity restructuring retrospective. But I think you may be missing a point. Even back in the late 1990s, I believe it was understood that much of the efficiency gains promised by electricity restructuring were dynamic rather than static. Competition introduced by restructuring would lead not so much to lower short-run costs but rather lower long-run costs (through better planning, through investments that more closely fit demand, through appropriate firm entry/exit) — i.e. avoiding / mitigating “future” stranded costs. The California Energy Crisis of the early 2000s and the subsequent Financial Crisis ruined any chance of restructuring effecting such gains. So, one might consider the recent electricity restructuring “experiment” initiated by California and various East Coast states (New England, Pennsylvania, New York) as being incomplete.
While the past twenty years may not be that informative about the possible “supply-side” dynamic gains from electricity restructuring, it has been surprisingly informative about the possible “demand-side” dynamic gains — as demonstrated by your (and other EI researchers) work on solar panels, distributed generation, smart grids, and real time pricing. I wonder how much of what we have learned about the demand-side carries over to the supply-side.
Love the blog, been lurking on it for a while.
Incomplete restructuring is correct, the restructured states seem to be struggling with planning for the future a bit more than the are the traditionally regulated regions. Capacity markets have had loads of problems, and as I understand it, there’s no clear picture for the NE restructured states for how to do resource adequacy going forward. Continue tinkering with capacity markets? Get the energy markets right (pay higher spot prices to keep generators around and maybe even entice new ones)? Re-introduce more regulated procurement? California’s answer after the energy crisis was clear – put the CPUC back in charge of long term procurement.
And California is in a real mess too now…
I agree with Jun assessment. I would go further on the rationale (as reflected by my agricultural and industrial clients at that time) of “never again”–the utilities had demonstrated an inability to contain costs in constructing Diablo Canyon, SONGS and Helms, and FERC had gutted the ability for third parties to build turnkey plants. The utilities were very slow to adopt the low-cost combined cycle technology, so the only solution looked to be to walk away. Restructuring did establish the merchant industry which has been the leaders in developing renewable technologies and even rooftop solar. Again, we could have expected the utilities to drag their feet, so we have gotten institutional innovation that otherwise would not have happened.
Go forward, leaving the utility system only “strands” network infrastructure if we take the static view that the network will continue in its current state. Shareholders are still recovering their investment, and if they’ve been paying attention since 2007, they should know that overall demand has been falling. They will only be stuck with infrastructure costs if either they have had little foresight or if a sudden technological change accelerates customer exit. In the latter situation, this will only occur if distributed resource costs fall dramatically in which case the exit will probably be socially beneficial. Why should consumers be locked into a large scale network to protect shareholders?
Restructuring was marked by a sudden, dramatic change–opening the market on a single day, divesting generation assets within a few months. The current transformation is more gradual because it is house by house, business by business. Utilities can change their investment plans, and depreciation recovery allows them to recoup their past costs. We may be foregoing the benefits of a paid-up network, but we have almost never regretted such technological change in the past. (Maybe the sale of the “red cars” rail system in LA as the most salient exception.) Do we regret that we’ve left behind land lines for our cell phones? Given the benefits of carrying around microcomputers for daily activities, I think not.
I nearly cried when I saw my brother-in-law’s electrical bill in Chicago: 5.5 cents per Kwh and no tiers. I asked him why and he said nuclear, [probably partly amortized] Nat Gas and coal. How is this explained? I pay an average closer to 3-4 times that! By the way, where is IPP defined?
IPP = Independent Power Producer? This is my deduction based on the map above showing high percentages for states like Pennsylvania which allows retail choice for electricity.
That’s correct. The working paper discusses this in more detail. Data are from EIA at http://www.eia.gov/electricity/data/state/
It would be easy to avoid customers installing wasteful storage “in order to avoid paying for fixed distribution charges.” Just don’t have fixed charges for distribution (or transmission or generation, as some utilities are now advocating). California IOUs have had no (or very small) fixed charges; they are now foolishly arguing for much higher fixed charges, which would, as you note, result in a huge waste of resources. Keep those customers on the grid, get some revenues from them (for supplemental and backup power), and maybe reduce their payment for power delivered to the grid (depending on the value of that excess), further reducing revenue requirements for other customers. Oh, and ensure that everyone with a suitable roof can install PV, so the poor are not excluded.
To be clear, I wasn’t arguing against fixed charges. The fact that utilities have very small fixed charges at the moment does not mean that they have small fixed costs. Someone has to pay for the wires. The problem now is that those fixed costs are being added to per KWh rates and that inflates the value of each KWh of distributed generation from the perspective of a ratepayer.
An alternative to adding those costs to fixed charges is to convert them in to demand charges, which is financially feasible now with AMR. See my “Curing the Death Spiral,” with Lori Cifuentes (Tampa Electric Company), Public Utilities Fortnightly, 2014 August.
I will speak on this topic next month at the NYAEE affiliate of USAEE.
The “problem” you identify is not a problem. Almost all the wire costs are driven by usage levels, not by the number of customers along the wires. The costs should be collected through usage charges. You seem to be stuck in the 1960’s mindset of “it’s a fixed cost [over the course of the year] so it must be collected through a fixed charge [independent of usage].”
Anyway, utilities face a choice: properly recover the costs of the distribution system in proportion to usage (or maybe on-peak usage) and lose some revenue when customers conserve, or impose large fixed charges and lose all the revenue as customers move to DG + storage and disconnect.
The distribution charge is divided into two parts, the first being the “wires” network that carries low voltage power to the final line transformer and the second being the service connection to the building. The former cost is sensitive to demand size; the latter is not so much due to substantial economies of scale. Hooking up a small duplex costs almost as much as a large mansion. It’s the latter cost that is the focus of the utilities’ customer charge proposal.
Mark, your solution is slightly better than a fixed monthly charge, but only slightly. What demand do you use? The customer’s non-coincident peak usually does not coincide with the system peak (a residential customer’s maximum demand is typically 5 times its contribution to system peak), or the variety of transmission-line, substation, feeder, line transformer, or (for multi-family) even service-drop peak. Using fancy metering, you could charge customers for their contribution to the system peak, which is a mediocre measure of contribution to reliability stress and generation-capacity need (since the critical supply hours may occur due to outages and ramping issues), and does not track well with the generation costs (since the fixed costs of coal,nuclear, and renewables are mostly energy-driven), transmission costs (driven by generation location and a variety of power flows), or substation, feeder, or transformer peak. And customers would need to watch the ISO demand level constantly to determine when to shift loads.
Small C/I customers do not understand their NCP demand charges or how to control them, and residential customers will understand them even less. So demand charges are likely to be nearly useless in giving any real incentives to small customers, and the incentives they get are unlikely to track costs well.
I agree a monthly demand charge is difficult for most customers to understand, especially since they feel penalized if they happen to slip up one day early or late in the month. But a daily demand charge may be easier to explain that TOU pricing. All you need to say on each day: “The more appliances you have on at the same time, the higher your price will be that day.”
Prices will summarize all of the relevant situations into a summary statistic. Customers need only pay attention to price–they don’t have to care about the CAISO, unless the CAISO issues a price forecast.
It’s hard to figure out how to indicate which comment you are responding to.
MCubeCon (9/29 5:53, on fixed charges): The economies of scale in transformers is not as great as you seem to think, and often adding a small customer does not require adding a transformer, so the incremental cost is demand-related. (And when a transformer is added, it is often because load is too high for the existing transformer, or the secondary distances are too great for the expected loads. Again, that’s load-related, not customer-number-related.
Adding a customer in a multi-family building adds nothing to the cost of the service drop (unless greater capacity is required).
Anyway, the CA utilities have proposed to include much more than the secondary-voltage system in the customer charge. SCE suggested that the“fixed charge could reflect both customer- and grid-related fixed costs of service” (CPUC Rulemaking 12-06-013, SCE Proposal, 5/29/2013, p. 16) and asserted that the “Proper Economic Recovery” method for all “customer” costs and “grid” costs would be through a fixed cost, and perhaps recover some variable load-related costs on yet another fixed charge based on the customer’s connected load (ibid, Table II-7). PGE claimed that for “capacity-related costs associated with generation, transmission, and distribution assets…it is more appropriate to collect these types of costs through a fixed monthly charge…” and suggested that “cost of programs like those that provide incentives for energy efficiency” should also be collected through the fixed charge (Testimony of Keane, Quadrini, and Zelmar, 2/28/2014, pp. 2-6 to 2-7).
MCubeCon (9/29 5:58, on demand charges): A daily demand charge does not track any cost I can think of. It would encourage customers to shift load off their own peaks (at 6 am, or midnight, or whatever), perhaps onto the equipment peak. How would it be superior to an energy charge?
You seem to be suggesting a real-time energy charge as an alternative, perhaps based on the customer-specific load on each level of the utility system. That makes sense, but would be computation-intensive and you really need to produce customer-specific price forecasts so they know when to run the dishwasher (and so on) early and when delay. The CAISO does provide price forecasts purchased power, based on the market, but the utility will need to add in all the other costs. It’s complicated.
The transformer is a third or less of the residential interconnection cost. Most of its in the undergrounding of the service line. (I’ve spent a couple decades on this issue at the CPUC.)
I’m familiar with SCE’s “grid charge” methodology that they introduced in 2003. I agree that component is much more problematic. That’s why I made the distinction between distribution and customer service costs.
A daily demand charge would be priced by time of day as monthly demand charges are already priced (see a commercial rate schedule). I don’t see the complexity in this pricing beyond what utilities are already doing for all of their other customers. It’s a pretty simple step.
When rooftop solar companies size their equipment based on the amount of electricity used by a customer in the top tier, then the amount of money in the top tier needs to be examined, such as converting the non-generating part of the top tier into a demand charge, or a customer charge. Retail rate design seems to be driving the solar industry, and other industries. So we need to pay more attention to retail rate design.
Seems like the fraction of generation from independent generation is a poor measure of restructuring for the purposes of assessing the sensitivity of retail rates to gas prices and other spot market conditions. For example, even though a large fraction of California’s generation comes from independently-owned generation, a lot of independent generation is renewable and/or procured through long-term contracts. Hence its cost to ratepayers does not necessarily change with spot market conditions. (California’s “hybrid market” which relies extensively on both independent generation and long-term contracting, may be sui generis.) Conversely, rates in traditional regulated states may respond to gas prices depending on the fraction of gas generation in utility portfolios and mechanisms for passing through fuel costs in retail rates.
Fair enough. My sense is that the renewables aspect would have an effect only in the most recent couple of years. The main point is that natural gas for most of this sample is a reasonable proxy for the marginal cost of the marginal unit, and therefore the market price, in a market-based state. The fraction IPP is meant to reflect the portion of the generation assets being paid an amount that follows the market price. While long-term contracts would dampen this effect at a specific point I wouldn’t expect them to create a large deviation from the average effect. Its true that a regulated state that is dominated by gas generation should also move with the gas price, but this would only impact the operating cost and not the total cost of the plant.